Reservoir treatment

ABSTRACT

A method of treatment of a subterranean hydrocarbon-bearing reservoir, the reservoir comprising at least one porous and permeable rock formation, the reservoir being penetrated by a plurality of injection wells and one or more production wells, the injection wells sharing a common injection header for delivering an aqueous injection fluid to the injection wells, the method comprising: a. identifying a group of injection wells selected from the injection wells sharing the common injection header; b. determining a cumulative volume of the treatment stream that is to be supplied contemporaneously to all of the injection wells within the identified group; c. simultaneously transmitting the treatment stream only to the identified group of injection wells so as to inject the treatment stream into the reservoir, thereby treating the reservoir to improve the sweep efficiency of subsequently injected fluid.

The present invention relates to the treatment of hydrocarbon-bearing subterranean reservoirs. More particularly, the invention relates to the treatment of subterranean reservoirs into which injection fluids are injected, in order to improve hydrocarbon, e.g. oil, recovery, the treatment being designed to improve reservoir sweep efficiency.

In the first stage of hydrocarbon recovery the sources of energy present in the reservoir are allowed to move oil, gas and condensate to production wells(s), commonly known as producer(s), where they can flow or be pumped to a surface handling facility. A relatively small proportion of the hydrocarbon in place can usually be recovered by this means. A widely used solution to the problem of maintaining the energy in the reservoir and seeking to ensure that hydrocarbon is driven to the producing well(s) is to inject fluids down adjacent wells. This is commonly known as secondary recovery. Such adjacent wells are commonly known as injection wells or injectors.

The fluids, commonly termed injection fluids, normally used are water (such as aquifer water, river water, sea water, or produced water), or gas (such as produced gas, carbon dioxide, flue gas and various others). If the fluid encourages movement of normally immobile residual oil or other hydrocarbon, the process is commonly termed tertiary recovery or enhanced oil recovery (EOR).

A problem with secondary and tertiary recovery projects relates to the heterogeneity of reservoir rock strata. The mobility of the injected fluid is commonly different from that of the hydrocarbon and when it is more mobile various mobility control processes have been used to seek to make the sweep of the reservoir more uniform and the consequent hydrocarbon recovery more efficient. Such processes can have limited value when high permeability zones, commonly called thief zones or streaks, exist within the reservoir rock. The injected fluid thus has a low resistance route from the injection to the production well, In such cases the injected fluid might not effectively sweep the hydrocarbon from adjacent, lower permeability zones. When the produced fluid is re-used this can lead to fluid cycling through the thief zone to little benefit and at great cost, e.g. in terms of fuel for and maintenance of an associated pumping system.

Herein, the term ‘thief zone’ refers to any region of high permeability relative to the permeabilities of the surrounding rock, such that a high proportion of injected fluid flows through these regions. Such thief zones typically cannot be characterized by absolute values of permeability as the problem arises as a result of heterogeneity in the permeability of the reservoir rock and not absolute values; thus a thief zone may simply be a region of higher permeability than the majority of the reservoir rock that can be contacted by a fluid injected into an injection well.

In order to improve sweep efficiency, these ‘thief zones’ deep in the reservoir can be partially or totally blocked, generating a new pressure gradient and forcing injected fluid into lower permeability areas of the reservoir with high oil saturation. Herein, sweep efficiency is taken to mean a measure of the effectiveness of an enhanced oil recovery process that depends on the proportion of the volume of the reservoir contacted by the injection fluid.

Various physical and chemical treatments have been used to divert injected fluids out of thief zones in or near production and injection wells and thereby increase reservoir sweep efficiency. By reducing the permeability of the thief zones, loss of injection fluid to these thief zones is reduced for subsequently injected fluids, e.g. during secondary and/or tertiary recovery. Accordingly, the sweep efficiency associated with subsequent secondary and/or tertiary recovery processes is improved, as compared with prior to the treatment.

When the treatment is applied to a producing well it is usually termed a water (or gas etc.) shut-off treatment. When it is applied to an injection well it is termed a profile control or conformance control treatment.

In cases where the thief zone(s) are isolated from the lower permeability adjacent zones and when the completion in the well forms a good seal with the barrier (such as a shale layer or “stringer”) causing the isolation, mechanical seals or “plugs” can be set in the well to block the entrance or exit of the injected fluid. If the fluid enters or leaves the formation from the bottom of the well, cement can also be used to fill up the well bore to above the zone of ingress.

When the completion of the well allows the injected fluid to enter both the thief and the adjacent zones, such as when a casing is cemented against the producing zone and the cement job is poorly accomplished, a cement squeeze is often a suitable means of isolating the watered out zone.

Certain cases are not amenable to such methods by virtue of the fact that communication exists between layers of the reservoir rock outside the reach of cement. Typical examples of this are when fractures or rubble zones or washed out caverns exist behind the casing. In such instances chemical gels, capable of moving through pores in reservoir rock have been applied to seal off the swept out zones.

An example of a process that has been developed with the aim of reducing the permeability of a thief zone is provided in U.S. Pat. Nos. 6,454,003, 6,729,402 and 7,300,973. These patents disclose polymeric microparticles having labile (reversible) and non-labile internal cross links in which the microparticle conformation is constrained by the labile internal cross links. The microparticle properties, such as particle size distribution and density, of the constrained microparticle are designed to allow efficient propagation through the pore structure of hydrocarbon reservoir matrix rock, such as sandstone. On heating to reservoir temperature and/or at a predetermined pH, the labile internal cross links start to break allowing the particles to expand by absorbing the injection fluid (normally water). The expanded particle is engineered to have a particle size distribution and physical characteristics, for example, particle rheology, which allow it to impede the flow of injected fluid in the pore structure of the thief zone. In doing so it is capable of diverting chase fluid into less thoroughly swept zones of the reservoir.

Current use of conformance control treatments comprising thermally activated particles involves treating a given injection well with a suitable treatment fluid by pumping the fluid into a single injection well. This technique places a high demand on equipment and manpower. The technique is time intensive and therefore is often of limited practicality in areas where there is only a short time or good weather window available in which to carry out the treatment. It can also be impractical in locations where access to individual injection wells is difficult, both onshore and offshore, for example, where wells are located subsea. Offshore, the high cost of specialized intervention vessels required to transport and supply the treatment chemicals to a single subsea well means that these problems may be even more acute.

For instance, treatments using thermally activated particles have been accomplished by pumping the chemicals into injection wells directly from 130 bbl IMO (International Maritime Organization) shipping containers. Once a given injection well had received its chemical volume target, the IMOs and support equipment were disconnected and moved to the next well for treatment. Clearly, treating a plurality of injection wells sequentially is time consuming and costly.

It is an object of the present invention to provide a method which overcomes, or at least substantially reduces, the disadvantages associated with conventional reservoir treatment methods.

Accordingly, in a first aspect the invention relates to a method of treatment of a subterranean hydrocarbon-bearing reservoir, the reservoir comprising at least one porous and permeable rock formation, the reservoir being penetrated by a plurality of injection wells and one or more production wells, the injection wells sharing a common injection header for delivering an aqueous injection fluid to the injection wells, the method comprising:

-   -   identifying a group of injection wells selected from the         injection wells sharing the common injection header and         specifying for each of the injection wells of the identified         group a predetermined volume of a treatment stream wherein the         treatment stream comprises an aqueous dispersion of thermally         activated treatment particles, the thermally activated treatment         particles being present in the treatment stream at a         predetermined concentration;     -   determining a cumulative volume of the treatment stream that is         to be supplied contemporaneously to all of the injection wells         within the identified group;     -   providing the cumulative volume of the treatment stream by         dosing a concentrated aqueous surfactant solution and a         concentrated dispersion of thermally activated treatment         particles into the aqueous injection fluid stream that is         flowing through the common injection header over a predetermined         period of time;     -   simultaneously transmitting the treatment stream only to the         identified group of injection wells so as to inject the         treatment stream into the reservoir wherein the rate of         injection of the treatment stream into each of the identified         group of injection wells is controlled such that the         predetermined volume of treatment fluid is delivered to each         injection well of the identified group, thereby treating the         reservoir to improve the sweep efficiency of subsequently         injected fluid.

The concentrated dispersion of thermally activated treatment particles may be dosed into the aqueous injection fluid stream downstream of the point at which the concentrated aqueous surfactant solution is dosed into the treatment stream. This serves to disperse the thermally activated treatment particles in the aqueous injection fluid thereby forming the treatment stream. In particular, the surfactant helps to ensure that the thermally activated treatment particles do not clump together downhole and hence cause reduced injectivity into the reservoir. In addition, the surfactant ensures that the thermally activated treatment particles are in a water-wet state prior to injection into the reservoir.

In one possibility the specified predetermined volume of a treatment stream is determined based on at least one of: the injection pattern size, treatment zone thickness, porosity of the rock/formation, and the percentage of high permeability thief (e.g. the percentage of the injection pattern accounted for by a region or “thief zone” having a permeability higher than the majority of the rock/formation in the remainder of the injection pattern). Although the term “predetermined” is used herein this is not to be interpreted as meaning fixed or hardwired, it simply means selected, determined or calculated. In some possibilities the volume of a treatment stream is determined based on at least one of: the volume of the concentrated dispersion of thermally activated treatment particles and the volume of the concentrated surfactant solution that are dosed into the aqueous injection fluid. The volume of the concentrated dispersion of thermally activated treatment particles may be selected based on the percentage by weight of polymeric particles in the concentrated dispersion. The volume of the concentrated surfactant solution may be selected based on the concentration of surfactant in the concentrated surfactant solution. In some possibilities the volume of the treatment stream is selected based on the volume of a thief zone that is to be treated.

Preferably, transmission of the treatment stream is initiated for every one of the identified group of injection wells at the same time. Transmission of the treatment stream may be stopped for every one of the identified group of injection wells at the same time, i.e. the treatment may be coterminous for every one of the identified group of injection wells. Alternatively, transmission of the treatment stream into one or more of the injection wells of the identified group may be stopped at different times i.e. the treatment of the wells may not be coterminous.

Preferably, the thermally activated treatment particles may be polymeric. In particular, the thermally activated particles may comprise polymeric microparticles, e.g. as disclosed in U.S. Pat. Nos. 6,454,003, 6,729,402 and 7,300,973. The polymeric microparticles may be provided with a cross-linking agent, which comprises reversible (labile) cross-linkers and, preferably, non-labile cross-linkers. Typically, the polymeric microparticle conformation may be constrained by reversible (labile) internal crosslinks. The properties such as particle size distribution and density, of the constrained microparticles may be designed to allow efficient propagation through the pore structure of the reservoir rock, which may, for example, comprise sandstone. For instance, the polymeric microparticles may have an unexpanded volume average particle size diameter of from about 0.05 to about 10 microns.

On heating to reservoir temperature and/or at a predetermined pH, the reversible (labile) internal crosslinks start to break allowing the particle to expand by absorbing the injection fluid (normally water). The ability of the particle to expand from its original size (at the point of injection) depends only on the presence of conditions that induce the breaking of the labile crosslinker. It does not depend on the nature of the carrier fluid or the salinity of the reservoir water. The particles can propagate through the porous structure of the reservoir without using a designated fluid or fluid with salinity higher than the reservoir fluid. The expanded particle is preferably engineered to have a particle size distribution and physical characteristics, for example particle rheology, which allow it to impede the flow of injected fluid in the pore structure. In doing so it is capable of diverting subsequently injected fluid, typically, a subsequently injected aqueous fluid, into less thoroughly swept zones of the reservoir.

The rheology and expanded particle size of the particle can be designed to suit the reservoir, for example by suitable selection of the backbone monomers or comonomer ratio of the polymer, or the degree of reversible (labile) and irreversible crosslinking introduced during manufacture. Similarly, the amount of cross linker used will depend on the reservoir conditions, such as temperature, pH of reservoir brine, and the transit time of the injection fluid.

Preferably, the thermally activated particles are stable at temperatures up to 95° C.

Preferably, a commercially available surfactant solution and/or dispersion of thermally activated treatment particles may be used to form the treatment stream, with the most appropriate grade being selected for a given reservoir treatment.

An example of a suitable concentrated surfactant solution is EC9360A supplied by ONDEO Nalco Energy Services Canada, Inc., which comprises a 10-30% (w/w) aqueous solution of ethoxylated alkyl sulphate.

Suitable concentrated dispersions of thermally activated treatment particles include those supplied by Nalco Energy Services, L.P. under the trade mark BrightWater®. Various grades of BrightWater® are available, from slowest acting to fastest acting, these being EC9368A, EC9378A, EC9398A and EC9404A. BrightWater® contains thermally activated treatment particles that are activated by hydrolysis upon contact with water. Therefore, BrightWater® is usually supplied with the treatment particles suspended in light mineral oil, for example, a hydrotreated light distillate, to prevent hydrolysis before use and a surfactant is included in the dispersion to render the treatment particles oil-wet. BrightWater® is dispersible in water.

For instance, BrightWater® EC9378A is supplied as a dispersion including from 30 to 60% (w/w) hydrotreated light distillate oil and from 5 to 10% (w/w) of surfactant. The concentration of thermally activated treatment particles in the dispersion may be, for example, around 30% (w/w).

Preferably, the concentrated surfactant solution and the concentrated dispersion of thermally activated treatment particles are mixed with the aqueous injection fluid thereby forming the treatment stream in a volumetric ratio of concentrated surfactant solution to concentrated dispersion of from 1:1 to 1:5. A ratio of around 1:3 may be especially preferred.

The treatment stream may include, for example, approximately 1.8% by volume of the concentrated dispersion of thermally activated treatment particles and approximately 0.6% by volume of the concentrated surfactant solution. Thus, if the concentrated dispersion of thermally activated particles comprises 30% (w/w) of thermally activated treatment particles, then the treatment stream would comprise 0.54% (w/w) of thermally activated treatment particles.

Typically, the aqueous injection fluid may comprise synthetic brine, seawater, aquifer water or produced water.

Herein, a common injection header is a pipe arrangement that connects flowlines to several injection wellheads from a single injection fluid line.

Offshore, the common injection header will typically be located on a fixed platform, a floating platform or a floating production storage and offloading (FPSO) vessel. In the case where the wellheads are on the seabed, typically a common injection flowline will lead from the header to a template or manifold located on the seabed. Wellheads for at least some of the injection wells sharing the common injection header are typically located on the template; typically, the wells themselves may be spaced further apart than the wellheads on the template as a result of directional drilling away from the location of the template. There may be injection wells sharing the common injection header which have wellheads located away from the template. Typically, the wellheads comprise choke valves, operable to control flow rates into or to shut-off their associated injection wells.

In order to identify the group of injection wells, candidate injection wells in a given area of interest, e.g. in a region of the reservoir, are screened to identify those with poor sweep efficiency. Preferably, the screening process may comprise identifying production wells with low oil recovery factors. In particular, at least one production well where the produced fluids have a high water cut may be identified. The injection wells associated with the identified production wells may then be selected to form part of the group of injection wells identified for treatment.

Herein, water cut is understood to mean the ratio of water produced from a production well compared to the volume of total liquids produced. Water cuts of 80% or more may be considered to be high.

Preferably, the screening process may take into account well integrity, in order to avoid treating wells with a high risk of down time. The screening process may also consider the likelihood of other unintended consequences, e.g. economic, logistical, practical or reservoir production management consequences, of the treatment that could have an undesirable or unacceptable impact on the operation of the reservoir.

Accordingly, the screening process may rank the injection wells for treatment. It is envisaged that one or more combinations of injection wells would be identified for treatment.

Injection wells identified for treatment are then grouped according to their common injection header. Preferably, for each selected injection well, the associated production well(s) are also identified.

Preferably, the injection patterns (also referred to as “waterflood” patterns) associated with the selected injection wells are then determined. The term “injection pattern” refers to the area around an injection well that can be contacted by a fluid injected into the well. Typically the injection pattern is a polygonal shape. This polygonal shape is usually confined by the limit of ‘no-flow’ boundaries. ‘No-flow’ boundaries may be barriers such as sealing faults, the edge of the reservoir formation, or boundaries with adjacent patterns.

The predetermined volume of the treatment stream required to treat each of the injection wells identified for treatment is calculated from the parameters obtained by analysis of the injection pattern size, the treatment zone thickness, the porosity of the reservoir rock, and/or the percentage of high permeability thief zone. Herein, the porosity is the percentage of pore volume or void space, or that volume within a reservoir that can contain fluids.

At least some of the injection wells present that are not selected for treatment may be either swapped to gas injection or shut in for the duration of the treatment. The injection rates required for delivering the predetermined volumes of the treatment stream over the predetermined period of time are then selected for each of the injection wells in the identified group. Preferably, the injection rate selected for injecting the treatment stream into each injection well is similar to that used to inject injection fluid into the same injection well during standard secondary and/or tertiary operations. This increases the likelihood that the treatment stream will follow the same path as the injection fluid and therefore reduce the permability in the target volume of thief zone. Large variations in the injection fluid injection rate and the treatment stream injection rate may lead to the treatment stream following an alternative path so that the treatment may not have the desired effect.

Preferably, step-rate tests may be conducted before initiating the treatment, in order to ensure that any adjusted injection rates will not impact reservoir conformance. This process provides confidence that the adjusted injection rates would direct the treatment stream into the same zones as the previously injected fluid. It is important that the reservoir will be subjected to the same flow regime at the adjusted injection rates, as it was at the original injection rates.

Further injection rate adjustments may be implemented while the treatment is ongoing, e.g. using choke valves in the injection wellheads, in order to adjust the flow of the treatment stream into one or more of the selected injection wells.

The duration of the treatment of the group of injection wells may be determined by the injection rates achievable dependent on reservoir characteristics, such as size and/or time available and/or the desired reduction in volume of thief zones. Typically, the predetermined period of time may be up to three months in duration. For instance, the predetermined period of time may be from one week to six weeks in duration.

The concentrated surfactant solution and the concentrated dispersion of thermally activated treatment particles are kept apart prior to the treatment, and only come together once dosed into the aqueous injection fluid. Preferably, separate tanks are provided for the storage of the dispersion of thermally activated treatment particles and the surfactant solution. Preferably, these tanks are fixed, rather than mobile. Suitably, the tanks may have capacities of up to 600 bbl. Preferably, the tanks may each have a capacity of at least 150 bbl. Tanks having a capacity of around 400 bbl may be suitable. The tanks may require topping up during the treatment with the surfactant solution or the dispersion of thermally activated treatment particles, if necessary. However, it will generally be preferred that the tanks have sufficiently large capacities, such that no topping up is required.

Each tank may be provided with a discharge pump. One or more further pumps on a pump skid may be employed to help transmit the concentrated dispersion of thermally activated treatment particles and/or the concentrated surfactant solution to the common injection header.

When applying the invention offshore, the storage tanks and, preferably, any pumps associated therewith, e.g. a discharge pump and/or a pump skid, may be located on a rig, a platform or a floating production, storage and offloading (FPSO) facility or a ship alongside any of these facilities.

Optionally, more than one common injection header may be supplied from a given storage tank or pair of storage tanks. Therefore, more than one group of injection wells may be treated either sequentially or, preferably, simultaneously.

Preferably, dosing of the concentrated surfactant solution into the aqueous injection fluid flowing through common injection header may begin prior to dosing of the dispersion of thermally activated treatment particles thereby forming a pre-flush stream. The pre-flush stream may gradually flush away debris lodged in the surface piping, wellbore, or perforations. Preferably, the dosing of the surfactant solution into the common injection header to form the pre-flush stream commences with a low surfactant concentration e.g. 0.025% by volume, and is then stepped up to a higher concentration similar to the concentration to be used in the treatment stream.

Dosing rates for the concentrated surfactant solution and the concentrated dispersion of the thermally activated particles and/or their dosed volumes may be monitored, preferably in real or near-real time, for example, by using flow meters on the pump skid or by periodically determining the depth of fluid in each tank and converting this depth to a calibrated volume of fluid.

Advantageously, the dosing rates and/or dosed volumes may then be adjusted in response to this monitoring.

After the predetermined period of time has elapsed, the surfactant solution may continue to be added to the aqueous injection fluid flowing through the common injection header for a relatively short period of time, for example, of less than 1 hour, thereby forming a post-flush stream. The post-flush stream may flush any thermally activated treatment particles out of the injection wellbore and into the reservoir.

Preferably, the treatment will be designed to target a volume of thief zone within the reservoir, such that after the treatment the permeability of the thief zone is reduced by a factor of at least 10, e.g. by a factor of from 20 to 50. The targeted volume of thief zone will be a proportion of the total volume of thief zone.

Post treatment surveillance may be carried out to determine the success of the treatment.

Optionally, the method of treatment can be used to treat multiple layers or intervals of a reservoir in one treatment.

A second aspect of the invention provides a system for carrying out a treatment of a subterranean hydrocarbon-bearing reservoir, the reservoir comprising at least one porous and permeable rock formation, the reservoir being penetrated by a plurality of injection wells and one or more production wells, comprising:

-   -   a common injection header for delivering an aqueous injection         fluid to the injection wells;     -   a first fixed storage tank for storing a surfactant solution for         use in the treatment; and     -   a second fixed storage tank for storing a dispersion of         thermally activated particles for use in the treatment;         wherein the first fixed storage tank is connected to the common         injection header at a first tie-in point and the second fixed         storage tank is connected to the common injection header at a         second tie-in point, the second tie-in point being located         downstream of the first tie-in point such that, in use, the         surfactant solution and the dispersion of thermally activated         treatment particles can be added to an injection fluid stream in         the common injection header to provide a treatment stream.

Aspects and examples of the present invention may be of particular benefit in locations where there is a short time window for carrying out the treatment, e.g. due to harsh climatic conditions. In addition, the inventors in the present case have appreciated that contemporaneous control of injection flow into a plurality of injection wells may achieve more effective treatment of thief zones or streaks than a series of individual injections into individual wells.

In order that the invention may be well understood, and by way of example only, field trials conducted by the applicant relating to the present invention will now be described with reference to the accompanying drawings, in which:

FIG. 1 is a schematic of a system according to the invention;

FIG. 2 is a graph showing the results of a step rate test for a selected injection well;

FIG. 3 is a graph showing the treatment stream injection rate during treatment vs. the target rate during treatment of an injection well;

FIG. 4 is a graph showing the Water Oil Ratio (WOR) vs. Cumulative Oil Production for a production well before and after treatment of the reservoir;

FIG. 5 is a graph showing the Oil Production Rate at a production well before and after treatment of the reservoir.

The invention was conceived and developed with the following goals in mind:

-   -   to achieve more effective treatment of thief zones or streaks         and thereby to reduce the treatment time needed per injection         well;     -   to reduce health, safety and environmental (HSE) exposure by         removing the need to move pumps and tanks to each individual         well, and     -   to achieve cost savings through reduced equipment usage and         lower personnel time demands.

FIG. 1 shows a schematic of a system according to the invention. A common injection header 14, in which, in use, an injection fluid stream flows in the direction indicated by arrow A splits into two branches at a junction 17. One branch leads to two injection wells 18, 19, while the other branch leads to ten injection wells 20, 21, 22, 23, 24, 25, 26, 27, 28, 29. Booster pumps 30, 31 act to ensure that the injection fluid stream reaches the ten injections wells 20, 21, 22, 23, 24, 25, 26, 27, 28, 29. The 12 wells 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29 share the common injection header 14.

A first storage tank 1 for storing a surfactant solution is connected by a flowline 3 to a discharge pump 5, which in turn is connected via a further flowline 7 to a pump 10 located on a pump skid 9. A flowline 12 connects the pump 10 to the common injection header 14 at a first tie-in point 15.

A second storage tank 2 for storing a dispersion of thermally activated treatment particles is connected by a flowline 4 to a discharge pump 6, which in turn is connected via a further flowline 8 to a pump 11 located on the pump skid 9. A flowline 13 connects the pump 11 to the common injection header 14 at a second tie-in point 16. The second tie-in point 16 is located downstream of the first tie-in point 15 and upstream of the junction 17.

The storage tanks 1, 2 are fixed and each has a capacity of 400 bbl. The use of fixed storage tanks may be advantageous, because it can help to reduce vehicle movements—which may be logistically and environmentally beneficial—as compared with delivering from mobile tankers.

In the system shown in FIG. 1, there is only one tie-in location for each of the surfactant solution and the dispersion of thermally activated treatment particles. Accordingly, there is no need to move equipment and chemicals from well to well. This stationary pumping setup allows for a larger, more permanent secondary containment to be utilized, thus decreasing the possibility of fluid escaping. It also reduces personnel hazard exposure by reducing the required equipment movements and crane operations compared with the traditional application method, i.e. moving from well to well in sequence. For instance, in the case of the treatment of five injection wells this reduction is as much as 80%. Where a greater number of injection wells are treated, the reduction will accordingly be greater.

In this trial, the dispersion of thermally activated treatment particles that was used was BrightWater® EC9378A supplied by Nalco Energy Services, L.P. and the surfactant solution was EC9369A supplied by ONDEO Nalco Energy Services Canada Inc.

Operation of the system will be described within the following description of the field trial methodology.

The process of identifying the group of injection wells involved screening the injection wells penetrating the reservoir so as to identify those injection wells injecting into areas of the reservoir that suffer from poor sweep efficiency.

The screening process mainly comprised of identifying high water cut production wells with low recovery factors and then targeting their offset, i.e. associated, injection wells. Well integrity was also considered to avoid treating wells with a high risk of down time. These wells were then grouped by common injection header and screened for unintended consequences, e.g. economic or logistical consequences that might adversely affect reservoir operations.

Five of the injection wells 18, 20, 21, 22, 23 shown in FIG. 1 were selected for treatment. These injection wells supported eight production wells P1, P2, P3, P4, P5, P6, P7 and P8. The water cut at the start of treatment for each of these production wells is set out in Table 1 below. Production well P7 had the lowest water cut (50%) of the production wells supported by the selected injection wells, while production well P9 had the highest (91%).

TABLE 1 Production well Injection wells Water cut P1 18, 20, 22 88% P2 18, 22 88% P3 18, 20, 22 77% P4 18 74% P5 21 76% P6 21 61% P7 23 50% P8 23 91% Total

The non-selected injection wells 19, 24, 25, 26, 27, 28, 29 were shut in before initiating the treatment.

Each of the identified injection wells was analyzed for pattern size, treatment zone thickness, porosity of the formation, and percentage of high permeability thief (e.g. the percentage of the pattern size accounted for by a high permeability region or “thief zone”). The target treatment volumes for the treatment stream for each injection well were calculated from these parameters. These target treatment volumes were based on the volume of the concentrated dispersion of polymeric particles and the volume of the concentrated surfactant solution that are dosed into the aqueous injection fluid over the predetermined time period of the treatment. These volumes are, in turn, dependent upon the percentage by weight of polymeric particles in the concentrated dispersion and the concentration of surfactant in the concentrated surfactant solution. The required volume of the surfactant solution was roughly one third of that of the dispersion of thermally activated treatment particles. However, the person skilled in the art would understand that the target treatment volumes may also be based on the volume of treatment fluid that is formed over the predetermined time period of the treatment and the percentage by weight of polymeric particles in this treatment fluid.

Table 2 shows the targeted volumes for the concentrated dispersion of treatment particles and concentrated surfactant solution for each of the selected injection wells.

TABLE 2 Dispersion of treatment Surfactant solution Injection well particles target (gallons) target (gallons) 18 16792 5774 20 11994 4124 21 23988 8249 22 14393 4949 23 29985 10311 Total 97152 33407

Due to equipment time constraints and a limited good weather time window, the treatment was planned to take place over 18 days, including a two-day pre-treatment by a pre-flush stream, comprising the aqueous injection fluid dosed with surfactant solution alone, to gradually remove any debris from the header, flowlines and wellbores. Design criteria required the treatment stream to contain approximately 1.8% of the concentrated dispersion of thermally activated treatment particles by volume and 0.6% of the concentrated surfactant solution by volume. In order to accurately deploy the desired volume of treatment stream in each injector during the same treatment duration, injection rate adjustments were implemented to four of the five injectors. Knowing the desired volume of treatment stream each injector required along with the concentration guidelines, new injection rates were calculated for each injector and are presented in Table 3.

TABLE 3 Previous water Adjusted, water Injection well injection rate (bpd) injection rate (bpd) 18 1200 1400 20 1000 1000 21 1500 2000 22 1500 1200 23 3000 2500 Total 8200 8100

Step rate tests were conducted prior to initiating the treatment, in order to ensure the adjusted injection rates would not impact down-hole injection conformance. FIG. 2 presents the results of a test performed in injection well 22. The well head injection pressure (WHIP) was monitored over a range of injection rates to ensure hydraulically induced fractures were not opening or closing with the adjusted injection rate (indicated by line B). This process provided confidence that the adjusted injection rate would direct the treatment stream into the same zones as the previously injected fluid (the previous injection rate being indicated by line C).

Dosing the injection fluid with the concentrated surfactant solution to form a pre-flush stream commenced two days prior to dosing the injection fluid with the concentrated dispersion of thermally activated treatment particles, thereby providing a pre-flush stream to gradually flush away debris lodged in the surface piping, wellbore, or perforations. The flushing commenced with a low surfactant concentration, e.g. the concentrated solution may be dosed into the aqueous injection fluids at a rate of 0.025% by volume for one day, and subsequently was stepped up to a higher concentration similar to the concentration to be used during the treatment, e.g. the concentrated surfactant solution may be dosed into the aqueous injection fluid stream at a rate of 0.1% by volume for a further day. Once dosing with the concentrated dispersion of thermally activated treatment particles started, it continued in tandem with dosing of the concentrated surfactant solution for 16 days, followed by pumping away the small amount of remaining surfactant solution to flush any remaining treatment particles into the reservoir.

The volume of the concentrated dispersion of thermally activated treatment particles and of the concentrated surfactant solution dosed into the aqueous injection fluid to form the treatment stream were measured using periodic tank strap measurements. A tank strap measurement refers to taking a measurement of the fluid level in the tank, for example, by using a sight glass, and then using a look-up table to determine a calibrated volume for the tank contents.

Other means for measuring injection rates and volumes could be used, e.g. flow meters attached to the pump skid. Injection header samples could also be analysed to monitor the concentration of thermally activated treatment particles in the treatment stream.

Table 4 summarizes the actual volumes of the two concentrates delivered to each well against its design target (normalized to shipping received volumes). The dosing of the concentrated surfactant solution took place for four days more than the dosing of the concentrated dispersion of the thermally activated treatment particles.

TABLE 4 Total dispersion of treatment particles Total surfactant solution Injection injection (gallons) injection (gallons) well Target Actual Diff. Target Actual Diff. 18 16781 15829 −6% 5439 5335 −2% 20 11986 11974 0% 3885 3922 1% 21 23972 23306 −3% 7771 7601 −2% 22 14384 14083 −2% 4662 4563 −2% 23 29965 29116 −3% 9713 9373 −3% Total 97088 94308 −3% 31470 30794 −2%

The injected volume of the dispersion of thermally activated treatment particles was within three percent of the target for four of the five injection wells. Injection well 18 was under target by six percent due to under injecting for the majority of the treatment period. This under injection was not believed to be caused by plugging or reduced injectivity, rather it was due to underestimating the required WHIP to obtain the desired injection rate. As the treatment progressed, the under injection was noticed and the WHIP for injection well 18 was gradually increased to help make up lost chemical volume. Cumulative water injection over this period for injection well 18 was three percent beneath the target, while the remaining four wells averaged one percent under target. FIG. 3 illustrates this for injection well 18. In FIG. 3, line D joining the data points shows the injection rate and the horizontal line E is the target injection rate. The WHIP is indicated by the series of triangular data points.

Including the pre and post-flush periods, the five-well treatment spanned 18 days with an estimated 70% time saving compared with treating five wells sequentially. Not only did this allow the pumping equipment to be used for multiple other treatments, but a cost saving of 20% was also achieved. The cost efficiency gained through the batch scale treatment can be largely attributed to removing down time associated with moving equipment from well to well.

Generally, post-treatment surveillance can be broken down into two categories: injection and production. Injection surveillance is undertaken to identify the decrease in injectivity caused by the onset of particle expansion and blocking deep in the reservoir. When the treatment particles expand and aggregate, they partially block the pore throats in the thief zones and injection fluid is forced to move through lower permeability rock in the reservoir. This causes an increase in required injection pressure for a given injection rate. This increase is not large enough to cause excessive reduction in injection rates since the blocking effect is deep in the reservoir. Once a reduced injectivity response is noted, usually two to ten months after treatment, a production response can be expected in a further one to six months depending on well spacing and injection rates for the subsequently injected fluid.

A production response from these treatments was expected to begin 8 to 12 months after treatment. In order to ensure an early response would not be missed, post-treatment surveillance was implemented only two months after treatment. The main objective of production surveillance was to monitor the water to oil ratio (WOR). As the high permeability flow paths between the injection well and production well are partially blocked, injection fluid is forced to contact portions of the reservoir which had previously been unswept, reducing the amount of produced water and thus decreasing the WOR.

A step change was observed in the relationship between WHIP and injection rate from the time before the treatment particles were activated within the reservoir to the time after the treatment particles were activated in the reservoir. This step change can be explained as the treatment particles partially block the high permeability flow paths, forcing the injection fluid to take a more tortuous route through the reservoir. For injection wells 20 and 18, this step change occurred around six months after the treatment period, while for injection well 22 the step change occurred only three months after the treatment period.

Of the eight production wells potentially impacted P1, P2, P3, P4, P5, P6, P7, P8, four have shown clearly identifiable signs of a response within 17 months after treatment. Monitoring of the production wells is ongoing.

Production well P2, an offset production well of injection well 22, started showing signs of a production response roughly one month after the injectivity decrease at injection well 22. As seen in FIG. 4, the water oil ratio (WOR) dropped from 3.92 to 0.97. It has since climbed back to around 3.5, likely due to water breakthrough in new high permeability flow paths. In FIG. 4, the line F indicates the start of the treatment period, dashed line G is a forecast for WOR against cumulative oil production if no treatment had been carried out and shaded area H illustrates the incremental improvement on the forecast, as a result of the treatment.

FIG. 5 shows the metered oil production rate for production well P2. The incremental oil production arising from the treatment was calculated by comparing the post treatment oil rate increase associated with the decrease in WOR with the base forecast J, as depicted by the shaded area K. The line I indicates the start of the treatment period. The total production response for production well P2 through 14 months was over 20,000 barrels of oil which is in good agreement with the expected ultimate value.

The incremental oil production benefits achieved as a result of the concurrent treatment of the selected injection wells in the field trial are expected to continue for the next 18 to 36 months. 

1-14. (canceled)
 15. A method of treatment of a subterranean hydrocarbon-bearing reservoir, the reservoir comprising at least one porous and permeable rock formation, the reservoir being penetrated by a plurality of injection wells and one or more production wells, the injection wells sharing a common injection header for delivering an aqueous injection fluid to the injection wells, the method comprising: a. identifying a group of injection wells selected from the injection wells sharing the common injection header and specifying for each of the injection wells of the identified group a predetermined volume of a treatment stream wherein the treatment stream comprises an aqueous dispersion of thermally activated treatment particles, the thermally activated treatment particles being present in the treatment stream at a predetermined concentration; b. determining a cumulative volume of the treatment stream that is to be supplied contemporaneously to all of the injection wells within the identified group; c. providing the cumulative volume of the treatment stream by dosing a concentrated aqueous surfactant solution and a concentrated dispersion of thermally activated treatment particles into the aqueous injection fluid stream that is flowing through the common injection header over a predetermined period of time; d. simultaneously transmitting the treatment stream only to the identified group of injection wells so as to inject the treatment stream into the reservoir wherein the rate of injection of the treatment stream into each of the identified group of injection wells is controlled such that the predetermined volume of treatment fluid is delivered to each injection well of the identified group, thereby treating the reservoir to improve the sweep efficiency of subsequently injected fluid.
 16. A method according to claim 15 in which the specified predetermined volume of a treatment stream is determined based on at least one of: the injection pattern size, the treatment zone thickness, the porosity of the formation, and the percentage of the injection pattern volume accounted for by a region of higher permeability than the remainder of the formation in the injection pattern volume.
 17. A method according to claim 15 in which the specified predetermined volume of a treatment stream is determined based on at least one of: the volume of the dispersion of the thermally activated treatment particles and the volume of the concentrated surfactant solution that are dosed into the aqueous injection fluid over the predetermined time period of the treatment.
 18. A method according to claim 15 in which the volume of the dispersion of the thermally activated treatment particles is selected based on the volume of a thief zone that is to be treated, wherein a thief zone comprises a region of higher permeability than the remainder of the formation in the injection pattern volume.
 19. A method according to claim 17 in which the volume of the dispersion of the thermally activated treatment particles is selected based on the volume of a thief zone that is to be treated, wherein a thief zone comprises a region of higher permeability than the remainder of the formation in the injection pattern volume.
 20. A method according to claim 15, wherein transmission of the treatment stream is initiated for every one of the identified group of injection wells at the same time.
 21. A method according to claim 15, wherein the transmission of the treatment stream is stopped for every one of the identified group of injection wells at the same time.
 22. A method according to claim 20, wherein the transmission of the treatment stream is stopped for every one of the identified group of injection wells at the same time.
 23. A method according to claim 15, wherein the thermally activated treatment particles are polymeric.
 24. A method according to claim 15, wherein the surfactant solution is dosed into the injection fluid stream at a point upstream of the point at which the dispersion of thermally activated treatment particles is dosed into the injection fluid stream.
 25. A method according to claim 15, wherein the dispersion of thermally activated treatment particles comprises 35% (w/w) of thermally activated treatment particles.
 26. A method according to claim 15, wherein the surfactant solution and the dispersion of thermally activated treatment particles are present in the treatment stream at a ratio by volume of from 1:1 to 1:5
 27. A method according to claim 15, wherein the surfactant solution comprises ethoxylated alkyl sulphate.
 28. A method according to claim 15, wherein dosing of the surfactant solution to the common injection header begins prior to dosing of the dispersion of thermally activated treatment particles thereby forming a pre-flush stream
 29. A system for carrying out a treatment of a subterranean hydrocarbon-bearing reservoir, the reservoir comprising at least one porous and permeable rock formation, the reservoir being penetrated by a plurality of injection wells and one or more production wells, comprising: a common injection header for delivering an aqueous injection fluid to the injection wells; a first fixed storage tank for storing a surfactant solution for use in the treatment; and a second fixed storage tank for storing a dispersion of thermally activated particles for use in the treatment; wherein the first fixed storage tank is connected to the common injection header at a first tie-in point and the second fixed storage tank is connected to the common injection header at a second tie-in point, the second tie-in point being located downstream of the first tie-in point such that, in use, the surfactant solution and the dispersion of thermally activated treatment particles can be added to an injection fluid stream in the common injection header to provide a treatment stream.
 30. A system according to claim 29, wherein the system comprises more than one common injection header. 